1. Field of the Invention
This invention relates broadly to oil exploration and production. More particularly, this invention relates to methods for determining the viscosity and density of formation fluids.
2. State of the Art
Various methods and tools are used to describe reservoir fluid and formation properties in an oil well. Some of these methods and tools aim to determine the relative volume of oil, water, and gas, for example. Other methods and tools aim to qualitatively describe the reservoir oil. This can be done by sampling the oil and by determining the density and viscosity of the sampled oil. However, when the sampled fluid is contaminated with mud-filtrate, making a direct measurement of reservoir oil density and/or viscosity is difficult.
Using the Schlumberger Modular Formation Dynamics Tester (MDT), fluid samples can be taken from the formation wall. Modules in the MDT test the samples in a variety of ways and with appropriate sensors could provide density and viscosity measurements for the mixture sampled. If the mixture were pure formation fluid, characterization of the oil in the reservoir could be accurately determined. However, the fluid is nearly always contaminated with at least some drilling mud. This prevents an absolutely accurate characterization of the oil in the reservoir.
During the drilling process, mud is pumped into the wellbore surrounding the drilling tool. The mud serves several purposes. It acts as a buoyant medium, cuttings transporter, lubricant, coolant, as well as a medium through which downhole telemetry may be achieved. The mud is usually kept overbalanced, i.e. at a higher pressure than the pressure of the formation fluids. This leads to “invasion” of the mud into the formation and the buildup of mudcake on the borehole wall. This is the environment in which samples are taken with a tool such as the MDT. Although the MDT filters out the solids from the samples, mud filtrate is always present in the samples.
When the mud filtrate is immiscible with the formation fluids, it is possible to separate it from the formation fluids by centrifuge or by settling due to gravity. However, when a well is drilled with oil-based-mud (OBM) the filtrate may miscibly mix with the formation fluid. When samples are taken, the first samples are nearly all OBM and if one waits long enough the last samples are nearly all formation fluid. However, it is unlikely that even the last sample will be pure enough to provide highly accurate measurements of viscosity and density of the formation fluids.